NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2021
NOTE A - NATURE OF OPERATIONS
Chief E&D Holdings, LP (“Chief” or the “Partnership”) is a Texas limited partnership engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. Chief E&D (GP) LLC owns the 1% general partner interest in Chief. The Partnership’s limited partner interests are held by Class A and Class B limited partners. Chief Exploration & Development LLC, a Texas limited liability company, is a wholly owned subsidiary of Chief and is in the business of exploration, development and production of oil and natural gas. Chief Oil & Gas LLC, a Texas limited liability company, is a wholly owned subsidiary of Chief Exploration & Development LLC, and is in the business of operating oil and gas properties.
NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation/Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Chief, its wholly owned subsidiary Chief Exploration & Development LLC and its indirectly wholly owned subsidiary Chief Oil & Gas LLC. Intercompany transactions and balances have been eliminated in consolidation.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as a component of the estimate of asset retirement obligations. The Partnership’s oil and natural gas reserves estimates, which are inherently imprecise, are prepared in accordance with guidelines established by the Securities and Exchange Commission. Other significant estimates and assumptions include, but are not limited to, uncollected revenues and unpaid (accrued) expenses and certain expense allocations.
Cash and Cash Equivalents
The Partnership considers all highly liquid investments with maturity dates of no more than three months from the purchase date to be cash equivalents. The Partnership maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Partnership has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Accounts Receivable
The majority of the Partnership’s accounts receivable are due from either purchasers of oil and natural gas or participants in oil and natural gas wells that the Partnership operates. The Partnership sells its operated oil and gas production to various purchasers. Management believes that the loss of any single purchaser would not significantly affect operations. In addition, the Partnership may participate with other parties in the drilling, completion and operation of oil and gas wells. Accounts receivable from joint interest partners are due within 30 days and are stated at amounts due from the working interest owners. The Partnership reviews its need for an allowance on a periodic basis and writes off accounts receivable when they become uncollectible. The Partnership determines the allowance by considering the length of time past due, previous history, and the debtor’s ability to pay its obligation, among other things. As of and for the year ended December 31, 2021, no allowance for doubtful accounts or write-offs related to accounts receivable have been recorded. See Note K for discussion of affiliate receivable balance.
Natural Gas Sales
Through our marketing process, we sell natural gas to ultimate third-party customers at specified delivery points based on an agreed-upon fixed or index price, net of any price differentials. The Partnership recognizes revenue when control transfers to the customer. Based on the terms of the contracts, natural gas is delivered to a specified terminus point and customers take custody, title and risk of loss of the product, and therefore, control passes at the delivery point.
We utilize midstream and interstate pipeline companies to gather and transport our natural gas who in turn charge us a fee for their services. For these contracts, we concluded we are the principal in the arrangement, the ultimate third party is our customer and we recognize revenue on a gross basis with transportation and gathering expense presented separately on the statements of operations.
From time to time, the Partnership purchases natural gas to meet certain sales commitments and reflects these transactions gross in the income statement as both a sale and cost of purchased natural gas.
Lease and Well Overhead Reimbursements
The Partnership also receives certain overhead cost reimbursements associated with operated wells through joint operating agreements with working interest owners. These costs are viewed as reimbursements of general and administrative costs and have been netted with general and administrative expense.
Fair Value of Financial Instruments
Cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short maturity of those instruments. The Partnership believes that the fair value of its notes payable, along with long-term debt approximates its carrying value as a result of floating rate interest terms.
Derivative Activities
The Partnership recognizes all price risk management instruments and interest rate swaps as either assets or liabilities measured at fair value. The Partnership has presented the fair value of derivative assets and liabilities on a net basis in the accompanying consolidated balance sheets where the right of offset exists.
The Partnership has not designated any price risk management instruments or interest rate swaps as fair value or cash flow hedges during the year ended December 31, 2021.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Pipe and Equipment Inventories
Pipe and equipment inventories consist of lease and well equipment and parts on hand for future drilling activities. Pipe and equipment inventories are stated at the lower of cost or net realizable value under the weighted average cost method. There were no pipe and equipment inventories write-downs during the year ended December 31, 2021.
Investments in Unconsolidated Affiliates and Other Assets
Investments in unconsolidated affiliates in which the Partnership does not have significant influence over the operations of the investee are accounted for under the cost method, whereby the Partnership records the investment at cost and recognizes as income distributions received from the net accumulated earnings of the investee since the date of acquisition. The investment in Pablo Gathering LLC was $0 at December 31, 2021 and reflects the Partnership’s 7.83% membership interest at cost. The investment in Coal County Gathering, LLC was $0.1 million at December 31, 2021, with distributions of $0.1 million during the year ended December 31, 2021. The investment in Coal County Gathering LLC reflects the Partnership’s 10.95% interest at cost.
Long-Term Bonus Plans
The Partnership has several long-term incentive bonus plans to compensate certain employees, as follows:
2019, 2020 and 2021 Long-Term Incentive Plans - Each year the performance of the Partnership is evaluated to determine if a bonus is appropriate and the corresponding amount of the overall bonus. The Partnership made long-term incentive awards in 2019, 2020, and 2021 to compensate certain employees.
The 2019, and 2020 Long-Term Incentive Plans are discretionary in nature. The 2019 bonuses are paid to the employees each December in three ratable installments beginning in 2019. The 2020 bonuses are paid ratably over four installments beginning in 2020. Employees must continue employment with the Partnership to receive the bonus. While these plans are still in effect, no new awards are being granted pursuant to these plans. As of December 31, 2021, future maximum expected payout under these plans is estimated to be approximately $2.8 million. The Partnership accrues the costs of these long-term incentive programs on a ratable basis as the bonus is earned, which is typically commensurate with the service period required to receive the cash payment under the respective bonus plan. The 2021 Long-Term Incentive Plan is discretionary in nature and is calculated based on company performance and paid ratably over four installments starting in 2022. No costs were expensed or accrued for in 2021.
Oil and Natural Gas Properties
The Partnership follows the successful efforts method of accounting for oil and gas property acquisition, exploration, development, and production activities. Under this method, costs of productive exploratory wells, development dry holes and productive wells, and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but such costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities.
The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Wells that are drilled to geologic structures that are both developmental and exploratory in nature may require an allocation of costs to properly account for the results. The evaluation of oil and natural gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
Net capitalized costs of unproved property and exploration well costs are reclassified to proved property and well costs when related proved reserves are found. Costs to operate and maintain wells and field equipment are expensed as incurred.
Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on total proved reserves. Capitalized exploration well costs and development costs are amortized similarly by field based on only proved developed reserves.
The economic producibility of oil and natural gas reserves, including the estimate of total proved developed and proved undeveloped reserves used as the basis for determining depletion of our oil and natural gas properties, is based on the unweighted arithmetic average of the first day of the month commodity prices during the 12-month period ending on the consolidated balance sheet date and costs in effect as of the last day of the accounting period, which are held constant for the life of the properties. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices.
The Partnership’s long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes on a field-by-field basis. To determine if a field is impaired, the Partnership compares the carrying value of the field to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. The calculation of expected future net cash flows in impairment evaluations are mainly based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted reserves. No impairment indicators were identified for proved properties for the year ended December 31, 2021.
Unproved property costs and related leasehold expirations are assessed at least annually for potential impairment and when industry conditions dictate an impairment may be possible. No impairment indicators were identified on unproved properties. For the year ended December 31, 2021, the Partnership recorded well abandonment expenditures of $0.5 million. The Partnership recorded non-cash lease abandonment expenses of $9.1 million for leases currently expiring or expected to expire during the year ended December 31, 2022.
Property and Equipment
Property and equipment are mainly comprised of furniture and fixtures, office equipment, and leasehold improvements. These items are recorded at cost and are amortized on a straight-line method over their estimated useful lives ranging from 3 to 20 years. Maintenance and repairs are expensed as incurred.
Asset Retirement Obligations
U.S. GAAP requires that the present value of a legal liability for an asset retirement obligation is recorded in the period it is incurred. The asset retirement obligation primarily relates to the abandonment of oil and gas producing facilities and includes costs to dismantle and relocate, or dispose of producing platforms,
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
wells and related structures. When this liability is recorded, the carrying amount of the related asset is increased by the same amount. Over time, the liability is accreted each period toward its future value, and the capitalized cost is depleted under the unit-of-production method based on proved reserves of the related asset. Upon settlement of the liability, a gain or loss is recorded to the extent the actual cost differs from the recorded liability.
Annually, the Partnership reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Partnership evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an annual basis, the Partnership will accordingly update its assessment.
The following table summarizes the changes in the Partnership’s asset retirement obligation during the year ended December 31, 2021 (in thousands):
| | | | | | | | |
| 2021 |
| | |
| Beginning balance | $ | 26,754 |
| Incurred | | 3,548 |
| Revision in estimated cash flows | | 36,808 |
| Accretion expense | | 1,756 |
| Settlements and disposals | | (179) |
| | |
| Ending balance | $ | 68,687 |
Income Taxes
Generally, income or loss of the Partnership is allocated to the individual partners for inclusion in their respective tax returns. Accordingly, no provision is made for federal income taxes in the accompanying consolidated financial statements. Certain state and local jurisdictions impose income-based taxes which the Partnership is subject to, however, the impact of these taxes to the Partnership has been insignificant to historical results of operations.
As required by the uncertain tax position guidance in Accounting Standards Codification (“ASC”) 740, Income Taxes, the Partnership recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Partnership has no uncertain tax positions as of December 31, 2021.
Joint Operating Activity
Exploration and production activities may be conducted jointly with others and, accordingly, the consolidated financial statements reflect only the Partnership’s proportionate interest in such activities. The Partnership is periodically reimbursed by the other joint interest partners for certain overhead costs incurred on their behalf. For the year ended December 31, 2021, these reimbursed costs have totaled $13.1 million, and are reflected net within general and administrative expense in the consolidated statement of operations.
Risks and Uncertainties
Historically, the market for oil and natural gas has experienced significant price fluctuations. Prices are impacted by supply and demand, both domestic and international, seasonal variations caused by changing
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
weather conditions, political conditions, governmental regulations, the availability, proximity and capacity of gathering systems for natural gas, and numerous other factors. Increases or decreases in prices received could have a significant impact on the Partnership’s future results of operations, reserves estimates and financial position.
Estimating oil and gas reserves is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and gas prices, drilling and operating expenses, capital expenditures, and taxes. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas most likely will vary from the Partnership’s estimates.
NOTE C - FAIR VALUE MEASUREMENTS
The Partnership measures and discloses fair value in accordance with ASC 820, Fair Value Measurement (“ASC 820”). Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.
ASC 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
| | | | | | | | |
| Level 1 - | Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. |
| | |
| Level 2 - | Include other inputs that are directly or indirectly observable in the marketplace. |
| | |
| Level 3 - | Unobservable inputs which are supported by little or no market activity. |
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table provides fair value measurement information for net financial assets and liabilities measured at fair value on a recurring basis (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2021 |
| Description | | Level 1 | | Level 2 | | Level 3 | | Fair Value |
| | | | | | | | | | | | |
| Commodity derivatives (current) | | $ | – | | $ | (125,296) | | $ | – | | $ | (125,296) |
| Commodity derivatives (non-current) | | | – | | | (75,961) | | | – | | | (75,961) |
| | | | | | | | | | | | |
| Interest rate swaps liability (current) | | $ | – | | $ | (8,180) | | $ | – | | $ | (8,180) |
| Interest rate swaps liability (non-current) | | | – | | | (2,323) | | | – | | | (2,323) |
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Level 2 Fair Value Measurements
Derivative activity assets and liabilities - Fair value of natural gas price swaps, basis swaps, interest rate swaps and collars are generally based on quoted prices for similar contracts or instruments as determined by independent brokers. All derivative financial instruments are classified within Level 2 of the valuation hierarchy as quoted market prices are not available in active markets for identical instruments.
NOTE D - DERIVATIVE ACTIVITIES
Commodity Derivatives
The Partnership uses various derivative financial instruments, including natural gas price swaps, basis swaps and collars to execute a strategy to mitigate and maintain acceptable exposure to the risk of changes in future cash flows due to fluctuations in commodity prices. All derivative financial instruments are recorded at fair value. The fair value of the derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.
The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, recognizes its price risk instruments at fair value and the corresponding realized and unrealized changes in fair value in the consolidated statement of operations under the captions “Realized price risk management gain (loss)” and “Unrealized price risk management gain (loss)” for commodity derivative transactions and within “Realized interest rate derivatives loss” or “Unrealized interest rate derivatives gain” for interest rate swap contracts.
The Partnership has entered into derivative contracts with counterparties who the Partnership believes are credit worthy counterparties that are investment grade.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Set forth below are the summarized amounts, terms and fair values of outstanding commodity derivative instruments as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
Description and Production Period | | Total Volumes by Day (Mmbtu) | | Weighted Average Strike Price (Per Mmbtu) | | Fair Value (in thousands) |
| | | | | | | |
Natural Gas Swaps: | | | | | | |
| January - December 2022 | | 300,226 | | $2.81 | | $ | (94,835) |
January - December 2023 | | 217,397 | | $2.73 | | $ | (49,549) |
January - December 2024 | | 140,000 | | $2.77 | | $ | (17,600) |
January - December 2025 | | 40,000 | | $2.71 | | $ | (4,835) |
| | | | | | | |
Basis Swaps: | | | | | | | |
January - March 2022 | | (40,000) | | ($6.11) | | $ | (8,266) |
| | | | | | | |
| Collars: | | | | | | | |
| January - December 2022 | | 20,000 | | $2.35 - 3.69 | | $ | (7,421) |
| | | | | | | |
| Swaptions: | | | | | | | |
| January - December 2022 | | 10,000 | | $2.98 | | $ | (2,561) |
| January - December 2023 | | 20,000 | | $2.88 | | $ | (4,023) |
| | | | | | | |
| Three Way Collars: | | | | | | | |
| January - December 2022 | | 72,466 | | $2.76/3.31/3.93 | | $ | (12,214) |
| January - December 2023 | | 10,000 | | $2.50/3.40/3.79 | | $ | 47 |
Interest Rate Swaps
The Partnership uses various interest rate swaps as a strategy to mitigate and maintain acceptable levels of exposure to the risk of changes in future cash flows due to interest rate fluctuations. At December 31, 2021, the Partnership had $385.7 million of floating rate debt outstanding. The fair value of the interest rate swaps at December 31, 2021 is ($10.5) million. A portion of the interest rate exposure is managed by utilizing interest rate swaps to lock in the rate on a portion of outstanding debt. The following table summarizes the outstanding interest rate swaps.
| | | | | | | | | | | | | | | | | |
| Term | | Type | | Notional Amount
Outstanding (in
thousands)
December 31,
2021 |
| | | | | |
| 01/2021-12/2024 | | Receive floating based on 1-month LIBOR, pay fixed | | $ | 325,000 |
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
| | | | | | | | |
NOTE E - OIL AND NATURAL GAS PROPERTIES | | |
| | |
Oil and natural gas properties consist of the following as of December 31, (in thousands): |
| 2021 |
| | |
Proved oil and natural gas properties | $ | 2,078,077 |
Unproved oil and natural gas properties | | 78,760 |
Wells in progress | | 3,001 |
Accumulated depreciation, depletion and amortization | | (1,033,627) |
| | |
Oil and natural gas properties, net | $ | 1,126,211 |
For the year ending December 31, 2021 depletion expense related to the Partnership’s oil and natural gas properties was $120.3 million.
Capitalized Exploratory Well Costs
The following table summarizes the changes in the capitalized exploratory well costs during the year ended December 31, 2021 (in thousands):
| | | | | | | | |
| 2021 |
| | |
Balance, beginning of period | $ | 12,711 |
Additions to exploratory well costs | | 22,789 |
Reclassification to proved properties | | (28,844) |
Exploratory charges expensed | | (3,655) |
| | |
| Balance, end of period | $ | 3,001 |
Exploratory drilling costs capitalized for a period of greater than one year were $2.6 million as of December 31, 2021.
NOTE F - PROPERTY AND EQUIPMENT
Property and equipment consist of the following as of December 31, (in thousands):
| | | | | | | | | | | | | | |
| Useful Life
In Years | | 2021 |
| | | | |
| Furniture & fixtures | 5 | | $ | 3,003 |
| Office equipment | 3-5 | | | 7,029 |
| Leasehold improvements | 5-15 | | | 7,315 |
| Vehicles | 3 | | | 318 |
| | | | |
| | | | 17,665 |
| Accumulated depreciation and amortization | | | | (14,498) |
| | | | |
| Total property and equipment, net | | | $ | 3,167 |
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December 31, 2021
For the year ended December 31, 2021, depreciation expense related to property and equipment was $0.8 million.
NOTE G - NOTE PAYABLE - RELATED PARTY
The Partnership entered into a loan agreement with Trevor Rees-Jones (the “Subordinated Note”), the principal owner of the Partnership, on April 1, 2008, and the Subordinated Note was subsequently amended, most recently on May 11, 2018. The Subordinated Note and amendments indicate the outstanding principal of the note may reach $600.0 million and all outstanding and unpaid principal and interest is due on June 30, 2027.
Effective June 30, 2011, the unpaid principal balance of the loan bears interest at the lesser of (i) the Prime Rate plus 3% based on prime rates of J.P. Morgan Chase Bank of New York or (ii) the maximum rate of interest permitted to be charged on the loan under applicable law. Beginning on June 30, 2019, interest is paid on a quarterly basis. Prior to June 30, 2019, interest was paid in kind (added to the principal amount of the note) and accrued interest was compounded annually at the end of each calendar year and added to the outstanding principal balance of the loan.
The interest rate was 6.25% as of December 31, 2021. The loan is subordinate to the Texas Capital Bank credit agreement described in Note H. The initial funding of the loan consisted of a conversion of $100.0 million of partners’ capital interest into the note payable. For the year ended December 31, 2021, the interest incurred on this note was $6.0 million. The loan balance at December 31, 2021 was $60.0 million. The loan and security agreement contain covenants which relate only to the ongoing operation of the business; there are no financial covenants. There was no default under the Subordinated Note for the year ended December 31, 2021.
NOTE H - LONG-TERM DEBT
On March 6, 2013, Chief Exploration & Development LLC entered into a credit agreement with Texas Capital Bank, N.A. (the “Credit Agreement”). The original agreement has been amended, most recently on May 22, 2020. This amendment was accounted for as a modification and not an extinguishment. The Credit Agreement bears interest equal to the base rate advance, as defined (generally Prime Rate plus a margin of 1% to 2%), or London Interbank Offered Rate (“LIBOR”) plus a margin of 2% to 3%, depending on the amount outstanding. The Credit Agreement is collateralized by security interests in specific oil and natural gas properties defined as the borrowing base properties and the amended maturity date of the Credit Agreement is May 11, 2023. The Credit Agreement, as amended, has a current borrowing base of $575.0 million at December 31, 2021. The balance outstanding at December 31, 2021, was $385.7 million. The Credit Agreement contains certain restrictive financial covenants, including a minimum required current ratio, a maximum leverage ratio, and the maintenance of a minimum interest coverage ratio. There exists no default under the Credit Agreement for the year ended December 31, 2021.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
The Partnership has recorded debt issuance costs of $2.5 million as of December 31, 2021. These costs are recorded as a reduction to “Long-term debt” on the Partnership’s consolidated balance sheets and will be amortized to interest expense, net, over the life of the notes using the effective interest method. A reconciliation of long-term debt at December 31, 2021 to the amount contained in the consolidated balance sheets is as follows (in thousands):
| | | | | | | | |
| 2021 |
| | |
| Future maturities of long-term debt | $ | 385,650 |
| Less: Debt issuance costs | | (2,468) |
| | |
| Long-term debt | $ | 383,182 |
Debt Guarantee
The Partnership is party to certain loan agreements entered into by Southridge Energy, LLC, (“Southridge”), MSC Southridge, LLC (“MSC”) and Coal County Gathering, LLC in proportion to its interest in certain unconsolidated affiliates. The Partnership is responsible to provide for guarantees of its respective share of the outstanding debt. As of December 31, 2021, the Partnership’s proportionate share of outstanding debt under these arrangements is approximately $0.6 million. No amounts have been recorded in the consolidated balance sheets related to these proportionate guarantees.
Debt Maturity Schedule
The following is a schedule of future debt maturities, excluding the impact of amortizing debt issuance costs, under the various debt agreements discussed above, including the Note Payable - Related Party described in Note G, as of December 31, 2021 (in thousands):
| | | | | | | | |
| Year ending December 31, | Amount |
| | |
| 2022 | $ | – |
| 2023 | | 385,650 |
| 2024 | | – |
| 2025 | | – |
| 2026 | | – |
| Thereafter | | 60,000 |
| | |
| Total | $ | 445,650 |
NOTE I - COMMITMENTS AND CONTINGENCIES
Volume Commitment
The Partnership is party to a gas transportation contract which includes a firm minimum natural gas commitment of 120,000 Dth/day through October 2023 and escalates to 170,000 Dth/day through September 2033. To the extent the Partnership does not deliver natural gas volumes in sufficient quantities, we would be required to reimburse the counterparty an amount equal to the shortage multiplied by a deficiency fee of $0.69/Dth. The Partnership is currently meeting the existing delivery commitment; however, decreased drilling activity could impact the ability to meet these commitments in the future.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Operating Leases
The Partnership has entered into certain office lease agreements which call for escalating rent payments, including an arrangement with a related party. There are other certain arrangements for copier, postage machine, and compressor lease agreements. The leases have expiration dates through May 2025. The Partnership records rent expense on a straight-line basis over the lease term.
The following is a schedule of future minimum lease payments required under the various leases as of December 31, 2021 (in thousands):
| | | | | | | | |
| Year ending December 31, | Amount |
| | |
| 2022 | $ | 2,707 |
| 2023 | | 2,616 |
| 2024 | | 2,612 |
| 2025 | | 1,957 |
| Thereafter | | – |
| | |
| Total | $ | 9,892 |
Rent expense, including fees for operating expenses and consumption of electricity, are included in the consolidated statement of operations under the caption general and administrative and was $6.0 million for the year ended December 31, 2021.
Litigation
The Partnership is involved in ongoing legal and/or administrative proceedings arising in the ordinary course of business, none of which have predictable outcomes. Management believes none of these matters will have a material impact on the Partnership’s financial position, cash flows, or operating results.
Environmental
The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no liabilities of this nature exist at December 31, 2021.
NOTE J - MAJOR CUSTOMERS
During 2021, the Partnership had 10 customers accounting for approximately 97% of its total natural gas revenues. As alternative purchasers of oil and gas are readily available, the Partnership believes that the loss of these customers would not result in a material adverse effect on our ability to market future oil and gas production. The Partnership also had four customers that account for approximately 78% of the joint operations receivable balances at December 31, 2021. Within the oil and gas receivables balances at December 31, 2021, four customers represented approximately 76%.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
NOTE K - AFFILIATE RECEIVABLE
The Partnership is involved in various related-party transactions. The Partnership has a note payable with Trevor Rees-Jones, the principal owner of the Partnership, as discussed in Note G. Additionally, the Partnership incurs payroll expenses and general and administrative expenses on behalf of other entities in which Trevor Rees-Jones has an interest and on a monthly basis allocates costs to certain affiliated entities on an employee-by-employee basis or other systematic allocation method. During 2021, there were allocations made to the related entities of approximately $1.2 million for payroll expenses and $3.7 million for general and administrative expenses, respectively.
The affiliate receivable at December 31, 2021 consists of the following amounts (in thousands):
| | | | | | | | |
| 2021 |
| | |
| Rees-Jones family office | $ | 203 |
| Other | | 1,841 |
| | |
| Total | $ | 2,044 |
NOTE L - ALLOCATION OF PARTNERSHIP EARNINGS AND LOSSES
Generally, the Partnership’s earnings are allocated 1% to the General Partner and 99% to the Class A limited partners until their capital accounts equal any unreturned capital contributions plus a preferred return (the “Preference Amount”). After the Preference Amount has been achieved, earnings are generally allocated 1% to the General Partner, approximately 69% to Class A limited partners and approximately 30% to the Class B limited partners. Losses are generally allocated 1% to the General Partner, approximately 69% to Class A and 30% to Class B, except that the limited partners’ capital accounts may not be reduced below zero.
NOTE M - RETIREMENT PLAN
The Partnership provides a 401(k) retirement plan covering all eligible employees. The plan provides for discretionary employer contributions as determined by the Partnership or its management in addition to a $1.00 per $1.00 Partnership match of up to 3% of an employee’s salary, plus a $0.50 per $1.00 Partnership match on an additional 2% of an employee’s salary. The Partnership contributed $0.4 million for the match to the 401(k) retirement plan for the year ended December 31, 2021. There were no discretionary contributions for the year ended December 31, 2021.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
NOTE N - SUBSEQUENT EVENTS
On January 24, 2022, the Partnership entered into a definitive Partnership Interest Purchase Agreement with Chesapeake Energy Corporation to sell all Partnership interests for $1.6 billion in cash and approximately 7.6 million common shares for a total purchase price of $2.1 billion with an effective date of January 1, 2022. The transaction closed on March 9, 2022 and concurrently all outstanding debt and interest was paid off using proceeds from the transaction. Prior to closing, the Partnership terminated all interest rate swap positions resulting in net cash settlements of $6.6 million to the counterparties.
The Partnership evaluated the consolidated financial statements for subsequent events through March 31, 2022, the date the consolidated financial statements were made available to be issued.
NOTE O - SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES (unaudited)
Net Capitalized Costs
Capitalized costs related to our natural gas producing activities are summarized as follows:
| | | | | | | | |
| December 31,
2021
(in thousands) |
| | |
| Natural gas properties: | | |
| Proved | $ | 2,078,077 |
| Unproved | | 81,761 |
| | |
| Total | | 2,159,838 |
| | |
| Less accumulated depreciation, depletion and amortization | | (1,033,627) |
| | |
| Net capitalized costs | $ | 1,126,211 |
Unproved properties as of December 31, 2021 consisted mainly of leasehold acquired through direct purchases of oil and natural gas property interests. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Costs Incurred in Natural Gas Property Acquisition, Exploration and Development
Costs incurred in natural gas property acquisition, exploration and development, including asset retirement costs, are summarized as follows:
| | | | | | | | |
| December 31,
2021
(in thousands) |
| | |
| Acquisition of properties: | | |
| Proved properties | $ | 584 |
| Unproved properties | | 2,734 |
| Exploratory costs | | 22,789 |
| Development costs | | 102,477 |
| | |
| Costs incurred | $ | 128,584 |
The following table includes revenues and expenses associated directly with our natural gas producing activities for the periods presented. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations.
| | | | | | | | |
| December 31,
2021
(in thousands) |
| | |
| Natural gas sales | $ | 630,694 |
| Lease operating expenses | | (22,989) |
| Transportation and gathering expenses | | (160,928) |
| Exploration | | (3,655) |
| Depletion and depreciation, amortization, and accretion | | (122,851) |
| | |
| Results of operations from natural gas producing activities | $ | 320,271 |
Natural Gas Reserve Quantities
Our petroleum engineers and independent petroleum engineering firms estimated all of our proved reserves as of December 31, 2021. Independent petroleum engineering firm Netherland, Sewell and associates, Inc. estimated 100% of our estimated proved reserves (by volume) as of December 31, 2021.
Proved natural gas reserves are those quantities of natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Developed natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods where production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
The information provided below on our natural gas reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
Presented below is a summary of changes in estimated reserves for the periods presented:
| | | | | | | | |
| | December 31, 2021 |
| | Natural Gas
(mmcf) |
| | |
| Proved reserves, beginning of period | | 2,659,259 |
| Extensions, discoveries and other additions | | 315,443 |
| Revisions of previous estimates | | 80,707 |
| Production | | (197,101) |
| | |
| Proved reserves, end of period | | 2,858,308 |
| | |
| Proved developed reserves | | |
| Beginning of period | | 1,361,798 |
| End of period | | 1,574,537 |
| | |
| Proved undeveloped reserves | | |
| Beginning of period | | 1,297,461 |
End of period (a) | | 1,283,771 |
| | |
(a) As of December 31, 2021, there were no PUDs that had remained undeveloped for five years or more. The natural gas price used in computing our reserves as of December 31, 2021, was $2.391 per mcf, after basis differential adjustments. |
The following summary sets forth our future net cash flows relating to proved natural gas reserves based on the standardized measure:
| | | | | | | | |
| | Year Ended
December 31,
2021
(in thousands) |
| | |
Future cash inflows (a) | $ | 6,835,345 |
| Future production costs | | (480,067) |
| Future development costs | | (551,592) |
| | |
| Future net cash flows | | 5,803,686 |
| | |
| Less effect of a 10% discount factor | | (2,987,720) |
| | |
| Standardized measure of discounted future net cash flows | $ | 2,815,966 |
| | |
(a) Calculated using prices of $2.391 per mcf of natural gas, after basis differential adjustments. | | |
Chief E&D Holdings, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2021
| | | | | | | | |
| Year Ended
December 31,
2021
(in thousands) |
| | |
Standardized measure, beginning of period (a) | $ | 628,348 |
| Sales of natural gas produced, net of production costs and gathering, processing and transportation | | (446,777) |
| Net changes in prices and production costs | | 1,743,030 |
| Extensions and discoveries, net of production and development costs | | 258,414 |
| Changes in estimated future development costs | | 10,745 |
| Previously estimated development costs incurred during the period | | 125,990 |
| Revisions of previous quantity estimates | | 84,907 |
| Accretion of discount | | 62,835 |
| Changes in production rates and other | | 348,474 |
| | |
Standardized measure, end of period (a) | $ | 2,815,966 |
| | |
(a) Calculated using prices of $2.391 per mcf of natural gas, after basis differential adjustments. | | |
